Expandable casing anchor

ABSTRACT

A wellbore isolation device includes an expandable housing. The expandable housing has a first end portion and a second end portion. A scarf cut can extend helically about the housing at least partially between the first and second end portions. The scarf cut can have a cut width. The housing is diametrically expandable from a contracted state to an expanded state to set the housing against an inner diameter of a wellbore.

TECHNICAL FIELD

The present description relates in general to downhole tools used in the oil and gas industry and more particularly to, for example, without limitation, to wellbore isolation devices that incorporate an expandable casing anchor.

BACKGROUND OF THE DISCLOSURE

In the drilling, completion, and stimulation of hydrocarbon-producing wells, a variety of downhole tools are used. For example, during hydraulic fracturing operations it is required to seal portions of a wellbore to allow fluid to be pumped into the wellbore and forced out under pressure into surrounding subterranean formations. Wellbore isolation devices, such as packers, bridge plugs, and fracturing plugs (alternately referred to as “frac” plugs) are designed for this purpose.

Typical wellbore isolation devices include a body and a sealing element disposed about the body and used to generate a seal within the wellbore. Upon reaching a desired location within the wellbore, the wellbore isolation device is actuated by hydraulic, mechanical, electrical, or electromechanical means to cause the sealing element to expand radially outward and into sealing engagement with the inner wall of the wellbore, or alternatively with casing lining the wellbore, or the inner wall of other piping or tubing positioned within the wellbore. Upon setting the sealing element, the migration of fluids across the wellbore isolation device is substantially prevented, which fluidly isolates the axially adjacent upper and lower sections of the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is an elevation view of an exemplary well system, according to some embodiments of the present disclosure.

FIG. 2A is a partial cross-sectional view of the wellbore isolation device, according to some embodiments of the present disclosure.

FIG. 2B is a partial cross-sectional view of the wellbore isolation device in a set position, according to some embodiments of the present disclosure.

FIG. 3A is a partial cross-sectional view of the wellbore isolation device in a set position, according to some embodiments of the present disclosure.

FIG. 3B is a partial cross-sectional view of the wellbore isolation device in a set position with a received wellbore projectile, according to some embodiments of the present disclosure.

FIG. 4 is an isometric view of the expandable housing, according to some embodiments of the present disclosure.

FIG. 5A is partial cross-sectional view of the expandable housing in a contracted state, according to some embodiments of the present disclosure.

FIG. 5B is partial cross-sectional view of the expandable housing in an expanded state, according to some embodiments of the present disclosure.

FIG. 6 is partial cross-sectional view of the expandable housing, according to some embodiments of the present disclosure.

FIG. 7 is partial cross-sectional view of the expandable housing, according to some embodiments of the present disclosure.

FIG. 8 is partial cross-sectional view of the expandable housing, according to some embodiments of the present disclosure.

FIG. 9 is a partial cross-sectional view of the wellbore isolation device, according to some embodiments of the present disclosure.

FIG. 10 is an isometric view of the expandable housing, according to some embodiments of the present disclosure.

FIG. 11A is a side view of an isolation device with expandable housings in a contracted state, according to some embodiments of the present disclosure.

FIG. 11B is a cross-sectional view of an isolation device with expandable housings in an expanded state, according to some embodiments of the present disclosure.

In one or more implementations, not all of the depicted components in each figure may be required, and one or more implementations may include additional components not shown in a figure. Variations in the arrangement and type of the components may be made without departing from the scope of the subject disclosure. Additional components, different components, or fewer components may be utilized within the scope of the subject disclosure.

DETAILED DESCRIPTION

The detailed description set forth below is intended as a description of various implementations and is not intended to represent the only implementations in which the subject technology may be practiced. As those skilled in the art would realize, the described implementations may be modified in various different ways, all without departing from the scope of the present disclosure. Accordingly, the drawings and description are to be regarded as illustrative in nature and not restrictive.

The present disclosure is related to downhole tools used in the oil and gas industry and, more specifically, to wellbore isolation devices that incorporate an expandable casing anchor.

Wellbore isolation devices, such as frac plugs and bridge plugs can be used within the wellbore to seal portions of the wellbore to allow fluid to be pumped into the wellbore and forced out under pressure into surrounding subterranean formations. Wellbore isolation devices can be run into the wellbore to a selected location and be set at that location. The wellbore isolation device can allow for flow therethrough until the central passageway of the device is desired to be sealed. A wellbore projectile, such as a ball or dart may be conveyed or otherwise pumped to the wellbore isolation device to seal off the central passageway through the wellbore isolation device, to allow the wellbore projectile to form a hydraulic seal to isolate a desired zone.

According to at least some embodiments disclosed herein is the realization that a wellbore isolation device can be provided with fewer component parts as compared to prior art wellbore isolation devices. Further, according to at least some embodiments disclosed herein is the realization that a wellbore isolation device can be provided with a larger inner diameter, which may prove advantageous for increasing flow rates during production operations. Further, according to at least some embodiments disclosed herein is the realization that a wellbore isolation device can be provided with fewer component parts to allow for more controlled dissolution characteristics for the wellbore isolation device.

FIG. 1 is an elevation view of an exemplary well system 100 that may incorporate the principles of the present disclosure. As illustrated, the well system 100 may include a service rig 102 that is positioned on the Earth's surface 104 and extends over and around a wellbore 106 that penetrates a subterranean formation 108. The service rig 102 may comprise a drilling rig, a completion rig, a workover rig, or the like. In some embodiments, the service rig 102 may be omitted and replaced with a standard surface wellhead completion or installation, without departing from the scope of the disclosure. While the well system 100 is depicted as a land-based operation, it will be appreciated that the principles of the present disclosure could equally be applied in any sea-based or sub-sea application where the service rig 102 may be a floating platform or sub-surface wellhead installation, as generally known in the art.

The wellbore 106 may be drilled into the subterranean formation 108 using any suitable drilling technique and may extend in a substantially vertical direction away from the Earth's surface 104 over a vertical wellbore portion 110. At some point in the wellbore 106, the vertical wellbore portion 110 may deviate from vertical and transition into a substantially horizontal wellbore portion 112. In some embodiments, the wellbore 106 may be completed by cementing a string of casing 114 within the wellbore 106 along all or a portion thereof. In other embodiments, however, the casing 114 may be omitted from all or a portion of the wellbore 106 and the principles of the present disclosure may alternatively apply to an “open-hole” environment.

The system 100 may further include a wellbore isolation device 116 that may be conveyed into the wellbore 106 on a conveyance 118 that extends from the service rig 102. The wellbore isolation device 116 may include any type of casing or borehole isolation device known to those skilled in the art. Example wellbore isolation devices 116 include, but are not limited to, a frac plug, a bridge plug, a wellbore packer, a wiper plug, a cement plug, a sliding sleeve, or any combination thereof. The conveyance 118 that delivers the wellbore isolation device 116 downhole may be, but is not limited to, wireline, slickline, an electric line, coiled tubing, drill pipe, production tubing, or the like.

The wellbore isolation device 116 may be conveyed downhole to a target location within the wellbore 106. In some embodiments, the wellbore isolation device 116 is pumped to the target location using hydraulic pressure applied from the service rig 102. In such embodiments, the conveyance 118 serves to maintain control of the wellbore isolation device 116 as it traverses the wellbore 106 and provides the necessary power to actuate and set the wellbore isolation device 116 upon reaching the target location. In other embodiments, the wellbore isolation device 116 freely falls to the target location under the force of gravity. Upon reaching the target location, the wellbore isolation device 116 may be actuated or “set” and thereby provide a point of fluid isolation within the wellbore 106.

Even though FIG. 1 depicts the wellbore isolation device 116 as being arranged and operating in the horizontal portion 112 of the wellbore 106, the embodiments described herein are equally applicable for use in portions of the wellbore 106 that are vertical, deviated, curved, or otherwise slanted. Moreover, use of directional terms such as above, below, upper, lower, upward, downward, uphole, downhole, and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.

FIG. 2A is a partial cross-sectional view of the wellbore isolation device 116, according to one or more embodiments. As illustrated, the wellbore isolation device 116 (hereafter “the device 116”) may include an upper wedge member 206, a lower wedge member 208, and an expandable housing 210. The upper and lower wedge members 206, 208 can be solid rings with annular bodies. The expandable housing 210 may include an inner diameter sized to receive at least a portion of the upper wedge member 206 and the lower wedge member 208. In some embodiments, as illustrated, the outer surface of the upper wedge member 206 and the lower wedge member 208 and inner radial surfaces of the expandable housing 210 may be complimentary tapered or angled or otherwise configured to slidably engage one another in setting the expandable housing 210 in a wellbore (e.g., the wellbore 106 of FIG. 1). As described in more detail below, the expandable housing 210 may comprise a one-piece structure with a scarf cut that allows the expandable housing to radially expand as it moves with respect to the upper wedge member 206 and the lower wedge member 208.

In some embodiments, the device 116 may further include a tension mandrel 204 configured to engage the lower wedge member 208. In certain embodiments, the lower wedge member 208 can be integrated with the tension mandrel 204. In some embodiments, the device 116 may further include a setting sleeve 202 configured to engage an end of the upper wedge member 206. As discussed below, the setting sleeve 202 and the tension mandrel 204 may be coupled to a setting tool (not shown) that may be actuated to axially contract the device 116. The setting tool may operate via various mechanisms including, but not limited to, hydraulic setting, mechanical setting, setting by swelling, setting by inflation, and the like.

In such embodiments, the setting tool may be actuated to force the lower wedge member 208 upwardly by drawing the tension mandrel 204 upwardly such that the expandable housing 210 slides along the tapered outer surface of the upper wedge member 206 and the lower wedge member 208. The setting sleeve 202 can hold the upper wedge member 206 stationary relative to the lower wedge member 208. In certain embodiments, the tension mandrel 204 may overcome a shear force provided by a shear device, such as a shear pin attached to the lower wedge member 208. As the expandable housing 210 moves with respect to the upper wedge member 206 and the lower wedge member 208, the expandable housing 210 may radially expand, such as into engagement with the inner wall of a casing (e.g., the casing string 114 of FIG. 1). In other embodiments, however, the setting sleeve 202 may be omitted from the device 116 and the setting tool may alternatively engage the expandable housing 210 (directly or indirectly) and otherwise force the expandable housing 210 up the tapered outer surfaces of the upper wedge member 206 and the lower wedge member 208 such that it radially expands into its set position.

FIG. 2B is a partial cross-sectional view of the wellbore isolation device 116 in a set position, according to one or more embodiments. As illustrated, as the expandable housing 210 is radially expanded and forced into contact with the inner wall of a casing (e.g., the casing string 114 of FIG. 1), the expandable housing 210 is anchored by the frictional forces between the upper wedge member 206, the lower wedge member 208, the expandable housing 210, and the casing 114. In certain embodiments, the upper wedge member 206 and/or the lower wedge member 208 can include surface treatments such as rough surfaces and edges, wickers, hardened coatings (both metallurgical and non-metallurgical bonded), ratchet teeth, ceramic buttons, etc. to promote anchoring between the expandable housing 210 and the upper and lower wedge members 206, 208.

FIG. 3A is a partial cross-sectional view of the wellbore isolation device 116 in a set position and otherwise engaged against the casing 114 after the setting sleeve 202 and the tension mandrel 204 have been retracted.

FIG. 3B is a partial cross-sectional view of the wellbore isolation device 116 in a set position with a received wellbore projectile 201. Once the setting sleeve 202 and the tension mandrel 204 have been detached and removed, a wellbore projectile 201, such as a ball or a dart may be conveyed and otherwise pumped to the device 116 and may land on a seat defined on the upper wedge member 206 and/or an end of the expandable housing 210. The wellbore projectile 201 may be configured to seal off the central passageway through the device 116 and, as a result, the wellbore projectile 201 may form a hydraulic seal that effectively converts the device 116 into a type of frac plug or bridge plug within the wellbore 106.

With the wellbore projectile 201 landed on the upper wedge member 206 and the expandable housing 210 engaged against the casing 114, increasing the fluid pressure within the casing 114 may force the upper wedge member 206 deeper inside the interior of the expandable housing 210, which may place an increased radial force on the expandable housing 210 against the casing 114.

FIG. 4 is an isometric view of the expandable housing 210, according to one or more embodiments. As illustrated, the expandable housing 210 includes a generally annular body 212 that provides a first end portion 216 a with a first tapered surface 217 a and a second end portion 216 b with a second tapered surface 217 b.

An inner surface in the body 212 can define the tapered surfaces 217 a,b. The tapered surfaces 217 a,b can be configured to receive the upper and lower wedge members 206, 208 to expand the expandable housing 210 as described herein. The tapered surfaces 217 a,b can have ramp angles selected in conjunction with the angles of the upper and lower wedge members 206,208 and can further be selected to determine a desired expansion behavior of the expandable housing 210.

An outer surface of the body 212 can include surface treatments to prevent movement of the expandable housing 210 upon setting against the casing 114. Surface treatments can include, but are not limited to rough surfaces and edges, wickers, hardened coatings (both metallurgical and non-metallurgical bonded), ratchet teeth, ceramic buttons, etc. In certain embodiments, to promote sealing the body 212 can include rubber or other elastomeric coatings, or grooves for O-rings.

A scarf cut 218 is defined in the body 212 and extends at least partially between the first and second end portions 216 a,b. The scarf cut 218 can be a generally spiral or helically extending cut slot in the body 212. In certain embodiments, the scarf cut 218 can extend at least partially around the body 212 or around the circumference of body 212 more than once. The scarf cut 218 can be created by a variety of methods, including electrical discharge machining (EDM), sawing, milling, turning, or by any other machining techniques that result in the formation of a slit through the annular body 212.

FIG. 5A is partial cross-sectional view of the expandable housing 210 in a contracted state, according to one or more embodiments. As illustrated, the scarf cut 218 may extend between the first and second end portions 216 a,b at an angle 220 relative to one of the first and second end portions 216 a,b or any other suitable plane extending normal to a longitudinal axis of the expandable housing 210. In the illustrated embodiment, the angle 220 of the scarf cut 218 is defined in the body 212 relative to the second end portion 216 b. In some embodiments, the angle 220 of the scarf cut 218 may be about 10°, about 15°, or about 20°. In other embodiments, however, the angle 220 of the scarf cut 218 may be about 40°, about 45°, or about 50°. In some embodiments, the angle 220 of the scarf cut 218 may range between 0° and 45°. In some embodiments, the angle 220 of the scarf cut 218 may range between 5° and 30°. As the angle 220 of the scarf cut 218 decreases, a circumferential length 222 of the scarf cut 218 correspondingly increases. A greater circumferential length 222 of the scarf cut 218 advantageously enables a larger expansion potential of the expandable housing 210 without the expandable housing 210 completely separating when viewed from an axial perspective.

The scarf cut 218 permits diametrical expansion of the expandable housing 210 to the expanded state. The body 212 provides an outer diameter 214 a, an inner diameter 214 b, and a tapered diameter 214 c. The inner diameter 214 b is provided at the first and second end portions 216 a,b and the tapered diameter 214 c is provided at the reduced diameter portion provided by the tapered surfaces 217 a,b. Advantageously, due to the construction of the expandable housing 210, a large flow area can be provided through the inner diameter 214 b and the tapered diameter 214 c. During expansion of the expandable housing, the diameters 214 a-c can be increased to set the expandable housing 210 within the casing 114.

FIG. 5B is partial cross-sectional view of the expandable housing 210 in an expanded state, according to one or more embodiments. The expandable housing 210 may be shown with the expanded state exaggerated to illustrate features of the expandable housing 210.

In the expanded state, a gap 224 may be formed between opposing angled surfaces 219 a,b of the scarf cut 218. The angle 220 of the scarf cut 218 may be calculated such that when the expandable housing 210 moves to the expanded state, the opposing angled surfaces 219 a,b of the scarf cut 218 axially overlap to at least a small degree such that no axial gaps are created between the first and second end portions 216 a,b. Accordingly, the scarf cut 218 enables the expandable housing 210 to separate at the opposing angled surfaces 219 a,b and thereby enable a degree of freedom that permits expansion and contraction of the expandable housing 210 during operation. In certain embodiments, the first end portion 216 a is movable relative to the second end portion 216 b as the expandable housing 210 expands. In certain embodiments, the first end portion 216 a rotates or otherwise moves circumferentially relative to the second end portion 216 b during expansion. In certain embodiments, the first end portion 216 a converges and/or diverges circumferentially relative to the second end portion 216 b during expansion.

The expandable housing 210, upper wedge 206, and lower wedge 208 may be made of a variety of materials such as, but not limited to, a metal, a polymer, a composite material, and any combination thereof. Suitable metals that may be used for the expandable housing 210 include steel, brass, aluminum, magnesium, iron, cast iron, tungsten, tin, and any alloys thereof. Suitable composite materials that may be used for the expandable housing 210 include materials including fibers (chopped, woven, etc.) dispersed in a phenolic resin, such as fiberglass and carbon fiber materials.

In some embodiments, the expandable housing 210, upper wedge 206, and lower wedge 208 may be made of a degradable or dissolvable material. As used herein, the term “degradable” and all of its grammatical variants (e.g., “degrade,” “degradation,” “degrading,” “dissolve,” “dissolving,” and the like), refers to the dissolution or chemical conversion of solid materials such that reduced-mass solid end products by at least one of solubilization, hydrolytic degradation, biologically formed entities (e.g., bacteria or enzymes), chemical reactions (including electrochemical and galvanic reactions), thermal reactions, reactions induced by radiation, or combinations thereof. In complete degradation, no solid end products result. In some instances, the degradation of the material may be sufficient for the mechanical properties of the material to be reduced to a point that the material no longer maintains its integrity and, in essence, falls apart or sloughs off into its surroundings. The conditions for degradation are generally wellbore conditions where an external stimulus may be used to initiate or effect the rate of degradation, where the external stimulus is naturally occurring in the wellbore (e.g., pressure, temperature, etc.) or introduced into the wellbore (e.g., fluids, chemicals, etc.). For example, the pH of the fluid that interacts with the material may be changed by introduction of an acid or a base. The term “wellbore environment” includes both naturally occurring wellbore environments and materials or fluids introduced into the wellbore.

Suitable degradable materials that may be used in accordance with the embodiments of the present disclosure include borate glass, polyglycolic acid (PGA), polylactic acid (PLA), a degradable rubber, a degradable polymer, a galvanically-corrodible metal, a dissolvable metal, a dehydrated salt, and any combination thereof. The degradable materials may be configured to degrade by a number of mechanisms including, but not limited to, swelling, dissolving, undergoing a chemical change, electrochemical reactions, undergoing thermal degradation, or any combination of the foregoing.

Degradation by swelling involves the absorption by the degradable material of aqueous fluids or hydrocarbon fluids present within the wellbore environment such that the mechanical properties of the degradable material degrade or fail. Exemplary hydrocarbon fluids that may swell and degrade the degradable material include, but are not limited to, crude oil, a fractional distillate of crude oil, a saturated hydrocarbon, an unsaturated hydrocarbon, a branched hydrocarbon, a cyclic hydrocarbon, and any combination thereof. Exemplary aqueous fluids that may swell to degrade the degradable material include, but are not limited to, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, acid, bases, or combinations thereof. In degradation by swelling, the degradable material continues to absorb the aqueous and/or hydrocarbon fluid until its mechanical properties are no longer capable of maintaining the integrity of the degradable material and it at least partially falls apart. In some embodiments, the degradable material may be designed to only partially degrade by swelling in order to ensure that the mechanical properties of the expandable housing 210 formed from the degradable material is sufficiently capable of lasting for the duration of the specific operation in which it is utilized.

Degradation by dissolving involves a degradable material that is soluble or otherwise susceptible to an aqueous fluid or a hydrocarbon fluid, such that the aqueous or hydrocarbon fluid is not necessarily incorporated into the degradable material (as is the case with degradation by swelling), but becomes soluble upon contact with the aqueous or hydrocarbon fluid.

Degradation by undergoing a chemical change may involve breaking the bonds of the backbone of the degradable material (e.g., a polymer backbone) or causing the bonds of the degradable material to crosslink, such that the degradable material becomes brittle and breaks into small pieces upon contact with even small forces expected in the wellbore environment.

Thermal degradation of the degradable material involves a chemical decomposition due to heat, such as the heat present in a wellbore environment. Thermal degradation of some degradable materials mentioned or contemplated herein may occur at wellbore environment temperatures that exceed about 93° C. (or about 200° F.).

With respect to degradable polymers used as a degradable material, a polymer is considered to be “degradable” if the degradation is due to, in situ, a chemical and/or radical process such as hydrolysis, oxidation, or UV radiation. Degradable polymers, which may be either natural or synthetic polymers, include, but are not limited to, polyacrylics, polyamides, and polyolefins such as polyethylene, polypropylene, polyisobutylene, and polystyrene. Suitable examples of degradable polymers that may be used in accordance with the embodiments include polysaccharides such as dextran or cellulose, chitins, chitosans, proteins, aliphatic polyesters, poly(lactides), poly(glycolides), poly(?-caprolactones), poly(hydroxybutyrates), poly(anhydrides), aliphatic or aromatic polycarbonates, poly(orthoesters), poly(amino acids), poly(ethylene oxides), polyphosphazenes, poly(phenyllactides), polyepichlorohydrins, copolymers of ethylene oxide/polyepichlorohydrin, terpolymers of epichlorohydrin/ethylene oxide/allyl glycidyl ether, and any combination thereof. Of these degradable polymers, as mentioned above, polyglycolic acid and polylactic acid may be preferred. Polyglycolic acid and polylactic acid tend to degrade by hydrolysis as the temperature increases.

Polyanhydrides are another type of particularly suitable degradable polymer useful in the embodiments of the present disclosure. Polyanhydride hydrolysis proceeds, in situ, via free carboxylic acid chain-ends to yield carboxylic acids as final degradation products. The erosion time can be varied over a broad range of changes in the polymer backbone. Examples of suitable polyanhydrides include poly(adipic anhydride), poly(suberic anhydride), poly(sebacic anhydride), and poly(dodecanedioic anhydride). Other suitable examples include, but are not limited to, poly(maleic anhydride) and poly(benzoic anhydride).

Suitable degradable rubbers include degradable natural rubbers (i.e., cis-1,4-polyisoprene) and degradable synthetic rubbers, which may include, but are not limited to, ethylene propylene diene M-class rubber, isoprene rubber, isobutylene rubber, polyisobutene rubber, styrene-butadiene rubber, silicone rubber, ethylene propylene rubber, butyl rubber, norbornene rubber, polynorbornene rubber, a block polymer of styrene, a block polymer of styrene and butadiene, a block polymer of styrene and isoprene, and any combination thereof. Other suitable degradable polymers include those that have a melting point that is such that it will dissolve at the temperature of the subterranean formation in which it is placed.

In some embodiments, the degradable material may have a thermoplastic polymer embedded therein. The thermoplastic polymer may modify the strength, resiliency, or modulus of the expandable housing 210 and may also control the degradation rate of the expandable housing 210. Suitable thermoplastic polymers may include, but are not limited to, an acrylate (e.g., polymethylmethacrylate, polyoxymethylene, a polyamide, a polyolefin, an aliphatic polyamide, polybutylene terephthalate, polyethylene terephthalate, polycarbonate, polyester, polyethylene, polyetheretherketone, polypropylene, polystyrene, polyvinylidene chloride, styrene-acrylonitrile), polyurethane prepolymer, polystyrene, poly(o-methylstyrene), poly(m-methylstyrene), poly(p-methylstyrene), poly(2,4-dimethylstyrene), poly(2,5-dimethylstyrene), poly(p-tert-butylstyrene), poly(p-chlorostyrene), poly(?-methylstyrene), co- and ter-polymers of polystyrene, acrylic resin, cellulosic resin, polyvinyl toluene, and any combination thereof. Each of the foregoing may further comprise acrylonitrile, vinyl toluene, or methyl methacrylate. The amount of thermoplastic polymer that may be embedded in the degradable material forming the expandable housing 210 may be any amount that confers a desirable elasticity without affecting the desired amount of degradation. In some embodiments, the thermoplastic polymer may be included in an amount in the range of a lower limit of about 1%, 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, and 45% to an upper limit of about 91%, 85%, 80%, 75%, 70%, 65%, 60%, 55%, 50%, and 45% by weight of the degradable material, encompassing any value or subset therebetween.

With respect to galvanically-corrodible metals used as a degradable material, the galvanically-corrodible metal may be configured to degrade via an electrochemical process in which the galvanically-corrodible metal corrodes in the presence of an electrolyte (e.g., brine or other salt-containing fluids present within the wellbore). Suitable galvanically-corrodible metals include, but are not limited to, gold, gold-platinum alloys, silver, nickel, nickel-copper alloys, nickel-chromium alloys, copper, copper alloys (e.g., brass, bronze, etc.), chromium, tin, aluminum, iron, zinc, magnesium, and beryllium. Suitable galvanically-corrodible metals also include a nano-structured matrix galvanic materials. One example of a nano-structured matrix micro-galvanic material is a magnesium alloy with iron-coated inclusions. Suitable galvanically-corrodible metals also include micro-galvanic metals or materials, such as a solution-structured galvanic material. An example of a solution-structured galvanic material is zirconium (Zr) containing a magnesium (Mg) alloy, where different domains within the alloy contain different percentages of Zr. This leads to a galvanic coupling between these different domains, which causes micro-galvanic corrosion and degradation. Micro-galvanically corrodible magnesium alloys could also be solution structured with other elements such as zinc, aluminum, nickel, iron, carbon, tin, silver, copper, titanium, rare earth elements, et cetera. Micro-galvanically corrodible aluminum alloys could be in solution with elements such as nickel, iron, carbon, tin, silver, copper, titanium, gallium, et cetera.

In some embodiments, blends of certain degradable materials may also be suitable as the degradable material for the expandable housing 210. One example of a suitable blend of degradable materials is a mixture of PLA and sodium borate where the mixing of an acid and base could result in a neutral solution where this is desirable. Another example may include a blend of PLA and boric oxide. The choice of blended degradable materials also can depend, at least in part, on the conditions of the well, e.g., wellbore temperature. For instance, lactides have been found to be suitable for lower temperature wells, including those within the range of 60° F. to 150° F., and PLAs have been found to be suitable for well bore temperatures above this range. In addition, PLA may be suitable for higher temperature wells. Some stereoisomers of poly(lactide) or mixtures of such stereoisomers may be suitable for even higher temperature applications. Dehydrated salts may also be suitable for higher temperature wells. Other blends of degradable materials may include materials that include different alloys including using the same elements but in different ratios or with a different arrangement of the same elements.

In some embodiments, the degradable material may include a material that has undergone different heat treatments and therefore exhibits varying grain structures or precipitation structures. As an example, in some magnesium alloys, the beta phase can cause accelerated corrosion if it occurs in isolated particles. Homogenization annealing for various times and temperatures causes the beta phase to occur in isolated particles or in a continuous network. In this way, the corrosion behavior can be very different for the same alloy with different heat treatments.

In some embodiments, the degradable material may be at least partially encapsulated in a second material or “sheath” disposed on all or a portion of the expandable housing 210. The sheath may be configured to help prolong degradation of the expandable housing 210. The sheath may also serve to protect the expandable housing 210 from abrasion within the wellbore. The sheath may be permeable, frangible, or comprise a material that is at least partially removable at a desired rate within the wellbore environment. In either scenario, the sheath may be designed such that it does not interfere with the ability of the wellbore isolation device 116 to form a fluid seal in the wellbore.

The sheath may comprise any of the afore-mentioned degradable materials. In some embodiments, the sheath may be made of a degradable material that degrades at a rate that is faster than that of the underlying degradable material that forms the expandable housing 210. Other suitable materials for the sheath include, but are not limited to, a TEFLON® coating, a wax, a drying oil, a polyurethane, an epoxy, a crosslinked partially hydrolyzed polyacrylic, a silicate material, a glass, an inorganic durable material, a polymer, polylactic acid, polyvinyl alcohol, polyvinylidene chloride, a hydrophobic coating, paint, and any combination thereof.

In some embodiments, all or a portion of the outer surface of the expandable housing 210 may be treated to impede degradation. For example, the outer surface of the expandable housing 210 may undergo a treatment that aids in preventing the degradable material (e.g., a galvanically-corrodible metal) from galvanically-corroding. Suitable treatments include, but are not limited to, an anodizing treatment, an oxidation treatment, a chromate conversion treatment, a dichromate treatment, a fluoride anodizing treatment, a hard anodizing treatment, and any combination thereof. Some anodizing treatments may result in an anodized layer of material being deposited on the outer surface of the expandable housing 210. The anodized layer may comprise materials such as, but not limited to, ceramics, metals, polymers, epoxies, elastomers, or any combination thereof and may be applied using any suitable processes known to those of skill in the art. Examples of suitable processes that result in an anodized layer include, but are not limited to, soft anodize coating, anodized coating, electroless nickel plating, hard anodized coating, ceramic coatings, carbide beads coating, plastic coating, thermal spray coating, high velocity oxygen fuel (HVOF) coating, a nano HVOF coating, a metallic coating.

In some embodiments, all or a portion of the outer surface of the expandable housing 210 may be treated or coated with a substance configured to enhance degradation of the degradable material. For example, such a treatment or coating may be configured to remove a protective coating or treatment or otherwise accelerate the degradation of the degradable material of the expandable housing 210. An example is a galvanically-corroding metal material coated with a layer of PGA. In this example, the PGA would undergo hydrolysis and cause the surrounding fluid to become more acidic, which would accelerate the degradation of the underlying metal.

In some embodiments, the degradable material may be made of dissimilar metals that generate a galvanic coupling that either accelerates or decelerates the degradation rate of the expandable housing 210. As will be appreciated, such embodiments may depend on where the dissimilar metals lie on the galvanic potential. In at least one embodiment, a galvanic coupling may be generated by embedding a cathodic substance or piece of material into an anodic structural element. For instance, the galvanic coupling may be generated by dissolving aluminum in gallium. A galvanic coupling may also be generated by using a sacrificial anode coupled to the degradable material. In such embodiments, the degradation rate of the degradable material may be decelerated until the sacrificial anode is dissolved or otherwise corroded away.

Referring again to FIGS. 2A and 2B, exemplary operation of the expandable housing 210 in conjunction with the wellbore isolation device 116 is now provided. The wellbore isolation device 116 is run into the wellbore 106 (FIG. 1) with the expandable housing 210 in the contracted configuration, as shown in FIG. 2A. Upon reaching the target location within the wellbore 106, the wellbore isolation device 116 may be actuated to the set configuration, as described above, which radially expands the expandable housing 210 from the contracted state to the expanded state, as shown in FIG. 2B.

Moving the expandable housing 210 to the expanded state gradually increases the size of the scarf cut 218 as the diameter increases and allows the expandable housing 210 set against the casing 114 as the expandable housing 210 is expanded by the upper and lower wedge members 206,208. In the expanded state, the expandable housing 210 in conjunction with the upper wedge member 206 can receive the wellbore projectile 201 as shown in FIG. 3B to hydraulically seal flow through the expandable housing 210.

FIG. 6 is partial cross-sectional view of the expandable housing 210, according to one or more embodiments. In some embodiments, the expandable housing 210 may be retained in the contracted state using a retaining means and will only be moved to the expanded state upon overcoming the retention force of the retaining means. In FIG. 6, for example, the expandable housing 210 may be retained in the contracted state with an amount of material 640 remaining in the scarf cut 218. More particularly, the scarf cut 218 defined in the annular body 212 may not extend entirely through the body 212 between the first and second end portions 216 a,b. Rather, the scarf cut 218 may be stopped short such that a small amount of the material 640 of the expandable housing 210 may remain. The remaining material 640 may prevent the expandable housing 210 from expanding. Instead, the material 640 must first be sheared or otherwise fail before the expandable housing 210 can move to the expanded state.

FIG. 7 is partial cross-sectional view of the expandable housing 210, according to one or more embodiments. The expandable housing 210 of FIG. 7 may be retained in the contracted state using another retaining means, namely, a frangible member 740 that extends circumferentially across a portion of the scarf cut 218. In some embodiments, the frangible member 740 may be an annular ring that extends about the entire circumference of the body 212, including across a portion of the scarf cut 218. In other embodiments, however, the frangible member 740 may extend only partially about the circumference of the body 212, but nonetheless across a portion of the scarf cut 218.

The frangible member 740 may be made of a variety of materials configured to yield upon assuming a radial force, Suitable materials for the frangible member 740 include, but are not limited to, a composite material (e.g., fiberglass, carbon fiber, etc.), a plastic, rubber, an elastomer, a metal, any of the degradable materials mentioned herein, and any combination thereof. Similar to the remaining material 640 of FIG. 6, the frangible member 740 must first be sheared or otherwise fail before the expandable housing 210 can move to the expanded state, thereby preventing premature expansion of the expandable housing 210.

FIG. 8 is partial cross-sectional view of the expandable housing 210, according to one or more embodiments. The expandable housing 210 of FIG. 8 may be retained in the contracted state using another retaining means, namely, a bonding material 840 disposed within all or a portion of the scarf cut 218. The bonding material 840 may be configured to couple the opposing angled surfaces 219 a,b together and must be sheared or otherwise fail before the expandable housing 210 can move to the expanded state, which prevents premature expansion of the expandable housing 210.

The bonding material 840 may comprise any material or substance applied to and otherwise deposited in the scarf cut 218 to prevent separation of the opposing angled surfaces 219 a,b until the expandable housing 210 assumes the radial force sufficient to move the expandable housing 210 to the expanded state. Suitable materials that may be used as the bonding material 840 include, but are not limited to, a glue (e.g., weld glue, an industrial adhesive, etc.), an epoxy, a weld bead, braze, and any combination thereof.

FIG. 9 is a partial cross-sectional view of the wellbore isolation device, according to some embodiments of the present disclosure. In certain embodiments, the upper wedge member 206 and/or the lower wedge member 208 can include retaining features, including, but not limited to ratcheting teeth 207, 209 to promote anchoring between the expandable housing 210 and the upper and lower wedge members 206, 208.

For example, as shown in FIG. 9, the ratchet teeth 207 of the upper wedge member 206 can engage with the ratchet teeth 209 of the lower wedge member 208 as the wedge members 206, 208 are driven towards each other as described herein. In other embodiments, the wedge members 206, 208 can include other anchoring mechanisms including, lock rings, frictional mechanisms, and/or deformation.

FIG. 10 is an isometric view of the expandable housing, according to some embodiments of the present disclosure. An outer surface of the body 212 can include surface treatments to prevent movement of the expandable housing 210 upon setting. For example, surface treatments can include ceramic buttons 213 disposed on the body 212 of the expandable housing. Surface treatments can further include, but are not limited to rough surfaces and edges, wickers, hardened coatings (both metallurgical and non-metallurgical bonded), ratchet teeth, ceramic buttons, etc.

FIG. 11A is a side view of an isolation device with expandable housings in a contracted state, according to some embodiments of the present disclosure. Referring to FIG. 11A, a wellbore isolation system 300 can include one or more expandable housings 210 to be used in conjunction with a wellbore isolation device 301. As illustrated, the expandable housings 210 described herein can be used to selectively expand and anchor the wellbore isolation device 301. The wellbore isolation device 301 can include an expandable sealing element 303 disposed around the mandrel 305. The expandable housings 210 can be disposed around the mandrel 305.

FIG. 11B is a cross-sectional view of an isolation device with expandable housings in an expanded state, according to some embodiments of the present disclosure. Referring to FIG. 11B, the expandable housings 210 can be expanded by wedges or other devices within the wellbore isolation device 301. During operation, the expandable sealing element 303 can expand to seal against the wellbore. As illustrated, the expandable housings 210 can be operatively coupled to the mandrel 305 to anchor the wellbore isolation device 301 within the wellbore. In certain embodiments, the expandable housings 210 can be coupled to any portion of the wellbore isolation device 301 to anchor the wellbore isolation device 301 within the wellbore. As shown, in certain embodiments, the expandable housings 210 can be used as anchoring devices for other downhole devices including, but not limited to the wellbore isolation device 301.

Various examples of aspects of the disclosure are described below as clauses for convenience. These are provided as examples, and do not limit the subject technology.

Clause 1. A wellbore isolation device, comprising: an expandable housing having a first end portion, a second end portion, and a scarf cut extending helically about the housing at least partially between the first and second end portions, the scarf cut defining a cut width, wherein the housing is diametrically expandable from a contracted state to an expanded state to set the housing against an inner diameter of a wellbore.

Clause 2. The wellbore isolation device of Clause 1, further comprising a wedge member with a tapered outer surface, wherein the tapered outer surface is engaged with the expandable housing in the expanded state.

Clause 3. The wellbore isolation device of Clause 2, wherein the scarf cut forms a first movable end segment adjacent to the first end portion and a second movable end segment adjacent to the second end portion, and wherein during diametric expansion, the first movable end segment moves circumferentially relative to the second movable end segment to set the housing against an inner diameter of the wellbore.

Clause 4. The wellbore isolation device of Clause 3, wherein the first movable end segment circumferentially converges toward the second movable end segment during expansion.

Clause 5. The wellbore isolation device of Clause 2, wherein the wedge member comprises an annular body.

Clause 6. The wellbore isolation device of any preceding Clause, further comprising a lower wedge member with a lower tapered outer surface, wherein the lower tapered outer surface is engaged with the housing in the expanded state.

Clause 7. The wellbore isolation device of Clause 6, wherein the lower wedge member includes a shear device to retain the lower wedge member relative to the housing.

Clause 8. The wellbore isolation device of Clause 6, wherein the lower wedge member comprises an annular body.

Clause 9. The wellbore isolation device of any preceding Clause, further comprising an upper wedge member with an upper tapered outer surface and a lower wedge member with a lower tapered outer surface, wherein the upper tapered outer surface and the lower tapered outer surface are engaged with the housing in the expanded state.

Clause 10. The wellbore isolation device of Clause 9, further comprising a setting sleeve disposed about the upper wedge member and a tension mandrel disposed about the lower wedge member, wherein the setting sleeve and the tension mandrel axially contract the upper wedge member and the lower wedge member in the expanded state.

Clause 11. The wellbore isolation device of any preceding Clause, further comprising a wellbore projectile disposed at the first end portion in the expanded state.

Clause 12. The wellbore isolation device of any preceding Clause, wherein the scarf cut extends along the housing at a scarf angle relative to a plane extending normal to a longitudinal axis of the device.

Clause 13. The wellbore isolation device of Clause 12, wherein the scarf angle is between about 0° and about 45°.

Clause 14. The wellbore isolation device of Clause 12, wherein the scarf angle is between about 5° and about 30°.

Clause 15. The wellbore isolation device of Clause 12, wherein the scarf angle is about 20°.

Clause 16. The wellbore isolation device of any preceding Clause, wherein the housing comprises a material selected from the group consisting of a metal, a polymer, a composite material, a degradable material, and any combination thereof.

Clause 17. The wellbore isolation device of Clause 16, wherein the degradable material is selected from the group consisting of borate glass, polyglycolic acid, polylactic acid, a degradable rubber, a degradable polymer, a galvanically-corrodible metal, a dissolvable metal, a dehydrated salt, and any combination thereof.

Clause 18. The wellbore isolation device of any preceding Clause, wherein the scarf cut provides opposing angled surfaces and an amount of material of the housing connects the opposing angled surfaces in the contracted state.

Clause 19. The wellbore isolation device of any preceding Clause, further comprising a frangible member extending circumferentially across a portion of the scarf cut to maintain the housing in the contracted state.

Clause 20. The wellbore isolation device of any preceding Clause, wherein the scarf cut provides opposing angled surfaces and a bonding material is disposed within at least a portion of the scarf cut to couple the opposing angled surfaces in the contracted state.

Clause 21. The wellbore isolation device of any preceding Clause, further comprising a mandrel and an expandable sealing element disposed about the mandrel, wherein the housing is operatively coupled to the mandrel to anchor the downhole device within the wellbore. Clause 22. A method, comprising: conveying a wellbore isolation device to a location within a wellbore, the wellbore isolation device including an expandable housing that provides a first end portion, a second end portion, and a scarf cut extending helically about the housing at least partially between the first and second end portions, the scarf cut defining a cut width; and actuating the wellbore isolation device from a contracted state to an expanded state and thereby increasing a size of the scarf cut to radially expand the housing to set the housing against an inner diameter of the wellbore.

Clause 23. The method of Clause 22, wherein the scarf cut forms a first movable end segment adjacent to the first end portion and a second movable end segment adjacent to the second end portion, and wherein during actuation, the first movable end segment moves circumferentially relative to the second movable end segment to set the housing against an inner diameter of the wellbore.

Clause 24. The method of Clause 23, wherein the first movable end segment circumferentially converges toward the second movable end segment during actuation.

Clause 25. The method of Clause 22-24, further comprising forcing a wedge member toward the housing to radially expand the housing.

Clause 26. The method of Clause 22-25, further comprising forcing a lower wedge member toward the housing to radially expand the housing.

Clause 27. The method of Clause 22-26, further comprising axially contracting an upper wedge member and a lower wedge member about the housing to radially expand the housing.

Clause 28. The method of Clause 27, further comprising axially contracting the upper wedge member and the lower wedge member between a setting sleeve and a tension mandrel.

Clause 29. The method of Clause 22-28, further comprising landing a wellbore projectile at the first end portion of housing after actuating the wellbore isolation device.

Clause 30. The method of Clause 22-29, wherein the scarf cut provides opposing angled surfaces and an amount of material of the housing connects the opposing angled surfaces, the method further comprising breaking the amount of material as the housing radially expands and thereby allowing the opposing angled surfaces to separate.

Clause 31. The method of Clause 22-30, wherein a frangible member extends circumferentially across a portion of the scarf cut, the method further comprising breaking the frangible member as the housing radially expands.

Clause 32. The method of Clause 22-31, wherein the scarf cut provides opposing angled surfaces and a bonding material is disposed within at least a portion of the scarf cut to couple the opposing angled surfaces, the method further comprising breaking the bonding material as the housing radially expands and thereby allowing the opposing angled surfaces to separate.

Clause 33. The method of Clause 22-32, wherein the scarf cut is defined in the housing at an angle relative to one of the first and second end portions, and wherein the angle is offset from perpendicular to the one of the first and second end portions.

Clause 34. The method of Clause 22-33, wherein the housing comprises a material selected from the group consisting of a metal, a polymer, a composite material, a degradable material, and any combination thereof.

Clause 35. The method of Clause 34, wherein the degradable material is selected from the group consisting of borate glass, polyglycolic acid, polylactic acid, a degradable rubber, a degradable polymer, a galvanically-corrodible metal, a dissolvable metal, a dehydrated salt, and any combination thereof.

Clause 36. The wellbore isolation device of Clause 22-35, further comprising anchoring a downhole device within the wellbore via the housing.

Clause 37. A well system, comprising: a casing disposed within a wellbore; and a wellbore isolation device conveyable within the wellbore and including: an expandable housing that provides a first end portion, a second end portion, and a scarf cut extending helically about the housing at least partially between the first and second end portions, the scarf cut defining a cut width, wherein the housing is diametrically expandable between a contracted state, wherein the housing, and an expanded state, wherein the housing is set within the casing.

Clause 38. The well system of Clause 37, wherein the scarf cut forms a first movable end segment adjacent to the first end portion and a second movable end segment adjacent to the second end portion, and wherein during diametric expansion, the first movable end segment moves circumferentially relative to the second movable end segment to set the housing against an inner diameter of the wellbore.

Clause 39. The wellbore isolation device of Clause 38, wherein the first movable end segment circumferentially converges toward the second movable end segment during expansion.

Clause 40. The well system of Clause 37-39, further comprising a wedge member with a tapered outer surface, wherein the tapered outer surface is engaged with the housing in the expanded state.

Clause 41. The well system of Clause 37-40, further comprising a lower wedge member with a lower tapered outer surface, wherein the lower tapered outer surface is engaged with the housing in the expanded state.

Clause 42. The well system of Clause 41, wherein the lower wedge member includes a shear device to retain the lower wedge member relative to the housing.

Clause 43. The well system of Clause 37-42, further comprising an upper wedge member with an upper tapered outer surface and a lower wedge member with a lower tapered outer surface, wherein the upper tapered outer surface and the lower tapered outer surface are engaged with the housing in the expanded state.

Clause 44. The well system of Clause 43, further comprising a setting sleeve disposed about the upper wedge member and a tension mandrel disposed about the lower wedge member, wherein the setting sleeve and the tension mandrel axially contract the upper wedge member and the lower wedge member in the expanded state.

Clause 45. The well system of Clause 37-44, further comprising a wellbore projectile disposed at the first end portion in the expanded state.

Clause 46. The well system of Clause 37-45, wherein the scarf cut is defined in the housing at an angle relative to one of the first and second end portions, and wherein the angle is offset from perpendicular to the one of the first and second end portions.

Clause 47. The well system of Clause 37-46, wherein the expandable housing comprises a material selected from the group consisting of a metal, a polymer, a composite material, a degradable material, and any combination thereof.

Clause 48. The well system of Clause 47, wherein the degradable material is selected from the group consisting of borate glass, polyglycolic acid, polylactic acid, a degradable rubber, a degradable polymer, a galvanically-corrodible metal, a dissolvable metal, a dehydrated salt, and any combination thereof.

Clause 49. The well system of Clause 37-48, wherein the scarf cut provides opposing angled surfaces and an amount of material of the expandable housing connects the opposing angled surfaces in the contracted state.

Clause 50. The well system of Clause 37-49, further comprising a frangible member extending circumferentially across a portion of the scarf cut to maintain the expandable housing in the contracted state.

Clause 51. The well system of Clause 37-50, wherein the scarf cut provides opposing angled surfaces and a bonding material is disposed within at least a portion of the scarf cut to couple the opposing angled surfaces in the contracted state.

Clause 52. The wellbore isolation device of Clause 37-51, further comprising a mandrel and an expandable sealing element disposed about the mandrel, wherein the housing is operatively coupled to the mandrel to anchor the downhole device within the wellbore. 

What is claimed is:
 1. A wellbore isolation device, comprising: an expandable housing having a first end portion, a second end portion, and a scarf cut extending helically about the housing at least partially between the first and second end portions, the scarf cut defining a cut width, wherein the housing is diametrically expandable from a contracted state to an expanded state to set the housing against an inner diameter of a wellbore.
 2. The wellbore isolation device of claim 1, further comprising a wedge member with a tapered outer surface, wherein the tapered outer surface is engaged with the expandable housing in the expanded state.
 3. The wellbore isolation device of claim 2, wherein the scarf cut forms a first movable end segment adjacent to the first end portion and a second movable end segment adjacent to the second end portion, and wherein during diametric expansion, the first movable end segment moves circumferentially relative to the second movable end segment to set the housing against an inner diameter of the wellbore.
 4. The wellbore isolation device of claim 1, further comprising a lower wedge member with a lower tapered outer surface, wherein the lower tapered outer surface is engaged with the housing in the expanded state.
 5. The wellbore isolation device of claim 1, further comprising an upper wedge member with an upper tapered outer surface and a lower wedge member with a lower tapered outer surface, wherein the upper tapered outer surface and the lower tapered outer surface are engaged with the housing in the expanded state.
 6. The wellbore isolation device of claim 5, further comprising a setting sleeve disposed about the upper wedge member and a tension mandrel disposed about the lower wedge member, wherein the setting sleeve and the tension mandrel axially contract the upper wedge member and the lower wedge member in the expanded state.
 7. The wellbore isolation device of claim 1, wherein the scarf cut extends along the housing at a scarf angle relative to a plane extending normal to a longitudinal axis of the device.
 8. The wellbore isolation device of claim 1, wherein the housing comprises a material selected from the group consisting of a metal, a polymer, a composite material, a degradable material, and any combination thereof.
 9. The wellbore isolation device of claim 8, wherein the degradable material is selected from the group consisting of borate glass, polyglycolic acid, polylactic acid, a degradable rubber, a degradable polymer, a galvanically-corrodible metal, a dissolvable metal, a dehydrated salt, and any combination thereof.
 10. The wellbore isolation device of claim 1, further comprising a mandrel and an expandable sealing element disposed about the mandrel, wherein the housing is operatively coupled to the mandrel to anchor the downhole device within the wellbore.
 11. A method, comprising: conveying a wellbore isolation device to a location within a wellbore, the wellbore isolation device including an expandable housing that provides a first end portion, a second end portion, and a scarf cut extending helically about the housing at least partially between the first and second end portions, the scarf cut defining a cut width; and actuating the wellbore isolation device from a contracted state to an expanded state and thereby increasing a size of the scarf cut to radially expand the housing to set the housing against an inner diameter of the wellbore.
 12. The method of claim 11, further comprising forcing a wedge member toward the housing to radially expand the housing.
 13. The method of claim 11, further comprising forcing a lower wedge member toward the housing to radially expand the housing.
 14. The method of claim 11, further comprising axially contracting an upper wedge member and a lower wedge member about the housing to radially expand the housing.
 15. The method of claim 14, further comprising axially contracting the upper wedge member and the lower wedge member between a setting sleeve and a tension mandrel.
 16. The method of claim 11, further comprising landing a wellbore projectile at the first end portion of housing after actuating the wellbore isolation device.
 17. The method of claim 11, wherein the scarf cut provides opposing angled surfaces and an amount of material of the housing connects the opposing angled surfaces, the method further comprising breaking the amount of material as the housing radially expands and thereby allowing the opposing angled surfaces to separate.
 18. A well system, comprising: a casing disposed within a wellbore; and a wellbore isolation device conveyable within the wellbore and including: an expandable housing that provides a first end portion, a second end portion, and a scarf cut extending helically about the housing at least partially between the first and second end portions, the scarf cut defining a cut width, wherein the housing is diametrically expandable between a contracted state, wherein the housing, and an expanded state, wherein the housing is set within the casing.
 19. The well system of claim 18, further comprising an upper wedge member with an upper tapered outer surface and a lower wedge member with a lower tapered outer surface, wherein the upper tapered outer surface and the lower tapered outer surface are engaged with the housing in the expanded state.
 20. The well system of claim 19, further comprising a setting sleeve disposed about the upper wedge member and a tension mandrel disposed about the lower wedge member, wherein the setting sleeve and the tension mandrel axially contract the upper wedge member and the lower wedge member in the expanded state. 